Hydrocarbon gas recovery methods

ABSTRACT

A method of recovery of rich gas where the rich gas is a hydrocarbon gas comprising less than 50 mole % methane is disclosed. The method comprises the steps of gathering the low pressure gas, compressing the gathered gas, cooling the compressed gas in a condenser so that a portion of the compressed gas condenses to form a liquefied gas and liquefied gas vapour in the condenser, and discharging the liquefied gas and liquefied gas vapour from the condenser, in which the cooling of the compressed gas is performed using at least one heat exchanger (40).

This invention relates to hydrocarbon gas recovery methods and, inparticular, to the recovery of hydrocarbon gas that is emitted duringthe extraction and treatment of crude oil which would otherwise bevented or flared.

Hydrocarbon gases are almost always associated with crude oil in an oilreserve, because they represent the lighter chemical fraction (shortermolecular chain) formed when organic remains are converted intohydrocarbons. Such hydrocarbon gases may exist separately from the crudeoil in the underground formation or they may be dissolved in the crudeoil. As the crude oil is extracted from the reservoir and raised to thesurface or subsequent to that process, the pressure in the crude oil isreduced to atmospheric pressure and dissolved hydrocarbon gases come outof solution. Such gases occurring in combination with the crude oil areoften referred to as “associated” gas.

At well pads where the production of oil and associated gas is of highvolume and high pressure, so called high producing well pads, it iseconomic to use existing technologies to separate the associated gasfrom the oil to produce what may be called “sales” gas and to processthe sales gas. The processing of the sales gas can produce pipelinequality natural gas and some purity products in the form of propane,butane, and gas condensate. The natural gas is introduced into a gaspipeline or a storage means for onward transmission and or sale, and thepurity products are generally sold and or stored separately. The salesgas generally comprises around 50% methane (CH₄), 20% ethane (C₂H₆), 13%propane (C₃H₈), 5% butane (C₄H₁₀), and the balance is heaverhydrocarbons.

At well pads where the production of oil and associated gas is of not ofhigh volume or high pressure, so called low producing well pads, it maynot be economic to install and use existing technologies to process thesales gas in the same way that it is processed at high producing wellpads. At such well pads, any gas that comes out of the oil may betreated as “flare” gas.

Once the crude oil has been extracted from the ground, it is generallypassed through a 2 phase separator with the intention of separating thesales gas from the oil. Thereafter the oil may undergo other processes,for example passing that oil through heater treater apparatus and/orstorage in a storage tank. Associated gasses are given off by the oilduring those other processes. Those gasses are at low pressure andgenerally contain little to no methane and the majority of the gas is amixture of ethane, propane and butane. This gas may be called rich gasbecause it is rich in ethane, propane and butane. For the purposes ofthis invention rich gas is defined as a hydrocarbon gas with a gascomposition comprising less than 50 mole % methane. These gasses arealso often known as “flare” gases. Again it is not economical to processthis rich gas in the same fashion as the sales gas is processed.

Historically rich gas has been considered to be a by-product or wasteproduct of oil production and this gas has been typically disposed of byventing or flaring (burning) that gas. Venting and flaring arerelatively inexpensive ways to deal with rich gas, but result inrelatively high emissions (e.g., large quantities of greenhouse gases)and fail to capture any of the energy contained within the gas.

Improved flaring systems and methods have been developed to reduce flareemissions sufficiently to satisfy stringent emission standards, however,many of these improved flaring systems merely convert the energy withinthe flare gas into thermal energy which releases to the environment.These improved flaring systems do not capture the energy containedwithin the flare gas.

Any flaring system is, in addition to its criteria pollutants, going tocontribute to carbon dioxide emissions (carbon footprint) generated bythe operator of the flare. There is ever increasing pressure on oilfield operators to reduce and minimise their carbon footprint.

Other gas utilization techniques such as bi-fueling diesel engines orfrac water heating have been tried, but those techniques have been foundto be challenged with marginal economics and rely on niche applicationsand/or a large volume throughput.

According to a first aspect of the present invention there is provided amethod of recovery of rich gas where the rich gas is a hydrocarbon gascomprising less than 50 mole % methane comprising the steps of

-   -   gathering the low pressure gas,    -   compressing the gathered gas,    -   cooling the compressed gas in a condenser so that a portion of        the compressed gas condenses to form a liquefied gas and        liquefied gas vapour in the condenser, and    -   discharging the liquefied gas and liquefied gas vapour from the        condenser,    -   in which the cooling of the compressed gas is performed using at        least one heat exchanger. The liquefied gas and liquefied gas        vapour is discharged into one or more storage means, for example        storage tanks.

The rich gas may have the further characteristic that it has a gaugepressure of less than or equal to 1379.0 kPa (200 psi), 689.5 kPa (100psi), or 344.7 kPa (50 psi).

The benefit of using at least one heat exchanger to cool the compressedgas and, as a result, cause it to condense is that heat exchangers are asimple and well established technology. This results in their beingrelatively inexpensive, reliable, and easy to maintain. A furtherbenefit is that the heat exchanger can be relatively small and as suchcan be operated (both in terms of operational conditions and in terms ofthe economics of operation) in situations where the volume of thecompressed gas will not be large, for example less than 1 m³. Thisability to operate on a small scale has the benefit that the method ofthe present invention can be deployed at well pads and other placeswhere the rich (flare) gas or mixture of rich (flare) and sales gassesare generated in small volumes.

The ability of the method and apparatus of the present invention tooperate economically in connection with rich gas that is generated atsmall volume is advantageous. This is because although any one suchlocation is likely to give rise to only a relatively small volume ofgas, failure to recover that small volume of gas at a large number ofsuch locations (for example, one or more oil fields which have a largenumber of well pads that each generate a small volume of flare gas) willlead to a large cumulative volume of non-recovered rich gas. That largevolume would, if flared, represent a large contribution to the oil fieldor operator's carbon footprint and associated emissions. The method andapparatus of the present invention thus provides a method of reducingthe volume of flared gas at locations of crude oil production and at oilproducing facilities.

In some embodiments of the present invention, the heat exchanger is afan-cooled condenser. In some embodiments, the heat exchanger iselectrically powered. In some embodiments the electricity powering theheat exchanger is generated by a generator powered by burning a portionof the gathered rich gas.

The rich gas may be gathered from one or more of a 2-phase separator, atreater unit, a vapour recovery tower, and an oil storage tank.Alternatively, the rich gas may be gathered from other sources.

The step of compressing the rich gas may be performed using one or moregas compressors such as compression pumps suitable for the compressionof gas. The input to each gas compressor is in fluid connection with atleast one source for gathering the rich gas. The output from each gascompressor is in fluid communication with the condenser and storagetank.

The rich gas gathered from each source may be compressed by a gascompressor dedicated to that source.

One or more of the gas compressors may be an oilless compression pump.

One or more of the gas compressors may be a variable speed compressionpump.

One or more of the gas compressors may operate continuously and the gascompressor may be configured to continuously compress a small flow rateof gas, for example around 0.2 m³ (7 cubic feet) of gas per minute. Insome examples the volume of gas to be compressed may be in the range of0.001 to 1.000 m³ per minute.

In some embodiments of the present invention, the or each gas compressoris controlled by a control unit, and the control unit comprises acentral processing unit and at least one pressure sensor adapted tomeasure the pressure of the incoming gas at the or each gas compressor.In some alternative embodiments, the or each gas compressor iscontrolled by a control unit, and the control unit comprises a centralprocessing unit and at least one pressure sensor adapted to measure thepressure of the rich gas at the or each source of such gas (the sourcepressure(s)), and the control unit may shut off a gas compressor if thesource pressure associated with that gas compressor falls below apredetermined minimum pressure.

In some embodiments, a central processing unit controls each gascompressor via an on/off switch or a variable speed controller. In someembodiments the central processing unit varies the speed of each gascompressor dependent on a source pressure measurement. In someembodiments when the pressure of the compressed gas is at or above apredetermined pressure the or each gas compressor is stopped. In someembodiments the pressure of the liquefied gas and vapour discharged fromthe condenser is measured and the central processing unit stops the oreach gas compressor if a predetermined pressure is exceeded.

It is known that for hydrocarbon gases, including rich gasses, there isa temperature, known as the dew point temperature, at which the gasstarts to condense and form a liquid. One of the factors whichdetermines the dew point temperature for a given gas, for example flaregas, is the pressure of the gas. It is the case that the higher thepressure of the gas, the higher the dew point temperature for the gas.For example, for a hydrocarbon gas at an absolute gas pressure of around2068 kPa (300 psia) the dew point temperature for that gas may be around−35 degrees Centigrade (−32 degrees Fahrenheit), whereas at an absolutegas pressure of around 4020 kPa (583 psia) the dew point temperature forthat gas may be around 16 degrees Centigrade (60 degrees Fahrenheit).

A further factor that will determine the dew point of a hydrocarbon gasis the composition of the gas. It has been found that the greater theamount of methane in the gas the lower the dew point temperature of thegas. It has been found that for hydrocarbon gases with a compositionthat includes more than 50 mole % methane the dew point of the gas is atvery low or cryogenic temperatures (less than −150 degrees Centigrade(−238 degrees Fahrenheit).

When the rich gas is compressed by the or each gas compressor thetemperature of the gas increases, for example the temperature of thecompressed gas may rise to around 150 degrees Centigrade (300 degreesFahrenheit). That hot compressed gas is pumped toward the condenser. Inexamples of the invention in which there are two or more sources of therich gas, the flows of hot compressed gas are merged in the condenser orbefore the flows of gas reach the condenser.

When the gas passes into the condenser, it may be cooled by the heatexchanger to a temperature of between about −18 to 27 degrees Centigrade(0 to 85 degrees Fahrenheit). Each compression pump runs to maintain acompressed gas gauge pressure of around 1724 kPa (250 psi), or in therange of 1379 to 2068 kPa (200 to 300 psi) or 1551 to 1896 kPa (225 to275 psi) in the condenser and each storage means. At these temperaturesand pressures at least a portion of the compressed gas will condense inthe condenser.

The condensate or liquefied gas formed in the condenser is a liquidcomprising one or more hydrocarbons such as ethane, propane and butane.The liquefied gas and liquefied gas vapours may pass out of an exit ofthe condenser, possibly in combination with some non-condensed gas. Insome examples of the present invention the sizing of the exit from thecondenser determines the rate of flow of the liquefied gas and vapourout of the condenser.

In some examples of the present invention when the heat exchange is afan-cooled condenser the fan is constantly running. The operation of thefan-condenser may be independent of the operation of the or eachcompression pump and/or independent of the pressure in the condenser.

In some embodiments of the present invention the liquefied gas,liquefied gas vapour and any non-condensed gas passes from the condenserinto one or more storage tanks. Each storage tank may be so constructedthat it can hold the liquefied gas, any associated vapour andnon-condensed gas at a gauge pressure of about pressure of about 1724kPa (250 psi) or in the range of 1379 to 2068 kPa (200 to 300 psi)011551 to 1896 kPa (225 to 275 psi) within an expected range oftemperatures. That expected range of temperatures may be the expectedrange of ambient temperatures at the location of each storage tank.

The storage tank may be fitted with a back pressure regulator tomaintain that pressure of about 1724 kPa (250 psi) or in the range of1379 to 2068 kPa (200 to 300 psi) or 1551 to 1896 kPa (225 to 275 psi)within an expected range of temperatures.

In some examples of the present invention each storage tank comprises alevel sensing means. That level sensing means may be in communicationwith a control unit for each compression pump. The control means maystop each compression pump if a predetermined level is reached in thestorage tank.

In embodiments where there are more than one storage tank, the controlmeans may additionally or alternatively be able to actuate a valve atthe entry to a storage tank or between the condenser exit and thestorage tank that prevents or allows the flow of liquefied gas andliquefied gas vapour and any non-condensed gas into the tank.

In some examples, the level sensing means may be in communication with aremote location, for example via the internet or other communicationsnetwork, so that the operator of the well pad at which the method of thepresent invention is being performed may know when the or each storagetank needs to be emptied.

The non-condensed gas exiting the condenser will, in terms of volume,energy, and/or carbon content be significantly smaller than the richgas. The non-condensed gas may be expected to comprise a higherproportion of methane than the rich gas. It may be vented from thestorage tank and introduced to a source of the rich gas, compressed andintroduced to a flow of rich gas from a compression pump to thecondenser, used to generate electricity via a gas burning generator,flared or disposed of in some other fashion.

In some examples of the present invention the or each compression pumpmay be controlled by a control unit. The control unit may comprise acentral processing unit and a memory. The memory may comprise a tablecontaining desired operating parameters for the method of the presentinvention including but not limited to minimum rich gas pressures at thesources of rich gas, minimum and maximum pressures (in the liquefied gasvapour or the liquefied gas) in the or each storage means. The controlunit may further comprise the sensors necessary to gather the data thatthe central processing unit requires to utilise the table in the memory.

The method of the present invention may further comprise a step ofremoving at least a portion of any sulphur, oxygen, and water present inthe rich gas before the condensing step. Including this step in themethod of the present invention has the advantage that it will remove atleast some of the undesirable impurities of sulphur, oxygen, and waterfrom the liquefied gas which is stored in the or each storage means.This step will also minimise the volume of the liquefied gas and thusmaximise the amount of useful liquefied gas that can be stored in the oreach storage means. A known gas cleanser may be used to remove the atleast a portion of any sulphur, oxygen, and water in the gas.

The at least one storage means may be a single storage tank ofsufficient size that it can store a known number of days, weeks ormonths production of liquefied gas. When such a storage tank issufficiently full, a transportation means, such as a road tanker, canvisit the storage tank and draw some or all of the contents of thestorage tank into the transport means. The liquid gas may then betransported to a location suitable for further processing of the liquidgas. Such transportation means are often configured to transport liquidgasses at a pressure of around 1724 kPa (250 psi) at ambienttemperature. It is thus an advantage of the present invention that theliquefied gas produced by the method of the invention may be at thatpressure and temperature because it makes the transfer of the liquefiedgas into the transportation means relatively simple

According to a second aspect of the present invention there is providedan apparatus suitable for liquefying and storing rich gas where the richgas is a hydrocarbon gas comprising less than 50 mole % methanecomprising a means for gathering rich gas, at least one means forcompressing the gathered gas, a means for condensing the compressed gasto form a liquefied gas, and at least one storage means, in which thecondensing of the compressed gas is performed using at least one heatexchanger. The advantages of the apparatus of the second aspect of thepresent invention are as discussed in connection with the method of thefirst aspect of the present invention.

The at least one heat exchanger may be a fan-cooled condenser.

The means for gathering the rich gas may comprise one or more conduitsproviding fluid communication between a source of the rich gas and atleast one compressor means.

The means for compressing the rich gas may be a gas compressor such as agas compression pump.

In some embodiments of the present invention, each gas compressor isassociated with a control unit and conduit means fluidly linking theoutput from the gas compressor to the heat exchange and a storage means,in which the control unit comprises a central processor unit and atleast one pressure sensor adapted to measure the pressure of the richgas at its source. The control unit may comprise further pressuresensors to measure the pressure of the compressed gas between the oreach gas compressor and the heat exchanger, and/or the liquefied gasafter it has passed through the heat exchanger. The liquefied gaspressure may be measured in the storage tank. The gas compressor may bespeed controlled with input from the rich gas source pressuremeasurement. The control unit may switch each gas compressor off whenthe pressure of the compressed gas between the or each gas compressorand the heat exchanger, and/or the pressure of the liquefied gas is ator above a predetermined pressure and or the source pressure of the richgas is below a predetermined pressure. A single control unit may controlmore than one gas compressor.

The control unit may comprise a central processing unit, a memory, atleast one pressure sensor adapted to source pressure of the rich gas,and at least one pressure sensor adapted to measure the pressure of theliquefied gas in the storage unit.

According to a third aspect of the present invention there is provided acomputer program product comprising computer readable instructions that,when run on a computer, is configured to cause a processer to performthe method of the first aspect of the present invention.

A computer program product may be provided for controlling at least onegas compressor, the computer program product comprising computerreadable instructions that, when run on one or more computers, areconfigured to cause one or more processers to determine the gas orliquefied gas pressures at different positions in the apparatus of thepresent invention, and to control the operation of the gas compressorsto keep the measured pressures within predetermined parameters.

The apparatus may further comprise a gas cleaner suitable for removingat least a portion of any sulphur, oxygen, and water from the gas.

In some embodiments of the present invention, the at least one storagemeans is a storage tank.

The present invention will be further described and explained by way ofexample and with reference to the drawings in which:

FIG. 1 shows a schematic embodiment of an apparatus according to thepresent invention operated by the method of the present invention; and

FIG. 2 shows an the schematic view of FIG. 1 including a control unit.

FIG. 1 shows a schematic view of a well pad. In which a flow of crudeoil 2 is introduced into a 2-phase separator 4. In the 2-phase separator4 sales gas separates from the oil and is drawn off via a conduit 6. Thesales gas is treated and introduced to a gas pipeline by means notshown.

The oil that has passed through the 2-phase separator 4 flows along aconduit 8 to a heater treater 10. After treatment in the heater treater10 the treated oil flows along a conduit 12 to a storage tank 14. Theoil is stored in the tank 14 until it is drained from the tank 14 viathe conduit 16 and transported elsewhere.

Whilst the oil is being treated in the heater treater 10 and sitting inthe storage tank 14 rich gas will come out of solution and collect ingas phase in the heater treater 10 and storage tank 14. The rich gas isremoved from the heater treater 10 via the conduit 18 to a divergenttwo-way junction 20 which includes a means (not shown) to direct the gasinto one or both of first and second exiting conduits 24, 26.

The first conduit 24 exits the junction 20 and is in communication witha high pressure flare 25.

The second conduit 26 allows the gas from the heater treater 10 to flowto a compression pump 48A in which it is compressed. The compressed gasflows from the compression pump 48A along a conduit 27 to a convergenttwo-way junction 28.

In the storage tank 14 rich gas builds up and, when released, flows to adivergent two way junction 32 via a conduit 30. Divergent two wayjunction 32 includes a means (not shown) to direct the gas into one orboth of first and second exiting conduits 33, 34.

The first conduit 33 exits the junction 32 and is in communication witha low pressure flare 35.

The second conduit 34 allows the gas from the storage tank 14 to flow toa compression pump 48B in which it is compressed. The compressed gasflows from the compression pump 48B along a conduit 37 to the convergenttwo-way junction 28.

Both of the compression pumps 48A and 48B are configured to compress therich gas to a gauge pressure of about 1724 kPa (250 psi) or in the rangeof 1379 to 2068 kPa (200 to 300 psi) or 1551 to 1896 kPa (225 to 275psi). When the rich gas is compressed by either of the compression pumps48A and 48B it increases in temperature, typically to around 150 degreesCentigrade (300 degrees Fahrenheit). At the convergent two-way junction28 the gas flowing along conduits 27 and 37 merges and the compressedgas flows along the conduit 36 to a heat exchange 40 which is afan-cooled condenser unit.

The heat exchange 40 cools the pressurised gas to a temperature that isabout equal to the ambient temperature around the heat exchange 40. Withthe cooling of the gas liquefied gas condenses out of the gas. Thepressure of the compressed gas is maintained within the heat exchange 40by the pumping action of one or both of compression pumps 48A and 48Bwhich compensates for any potential pressure drop due to cooling of thecompressed gas and/or the condensation of liquefied gas.

The liquefied gas and liquefied gas vapour exits the heat exchange 40via a conduit 42. The liquefied gas and liquefied gas vapour then entersa storage tank 44 and is held in that tank until that tank is emptiedinto a transportation means (not shown) via a drain means (70).

The conduit 72 exiting the storage tank 44 is provided with a backpressure control valve 78 set at 1724 kPa (250 psi). This maintains apressure of 1724 kPa (250 psi) in the storage tank but allowsgas/vapour/liquid gas to vent through conduit 72 to relieve excesspressure in the storage tank 44.

With reference to FIG. 2 and with continued reference to FIG. 1 , thegas pressure within the storage tank 40 is determined and controlled bya control unit 50 for the compression pumps 48A and 48B.

The control unit 50 comprises a central processing unit 52, a memory 54,a pressure sensor 56 adapted to measure the pressure of the compressedgas in the conduit 36, a pressure sensor 58 adapted to measure the richgas pressure in the conduit 26 which carries rich gas from the heatertreater 10, a pressure sensor 60 adapted to measure the rich gaspressure in the conduit 34 which carries rich gas from the storage tank14, and a level sensor 64 adapted to measure the level of the liquefiedgas in the storage tank 44. The gas pressure in the conduits 26 and 34is the pressure of the rich gas as it exits the heater treater 10 andstorage tank 14 respectively.

Each of the sensors 56, 58, 60, and 62 are in data communication withthe central processing unit 52 via one or more known data communicationmeans 74. For example, but without limitation, data communication means74 may be electrical wires, or via wireless networking.

The memory 54 of the control unit 50 comprises a table 64 relating tothe desired operating parameters of the apparatus, for example, minimumpressure readings in conduits 26 and 34, a maximum pressure in theconduit 36, and the maximum liquid level in the storage tank 44.

The central processing unit 52 uses the table 64 and input signals(representative of data) from the sensors 56, 58, 60, and 62 todetermine whether none, one, or both of the compression pumps 48A and48B should be running. The compression pumps 48A and 48B are controlledby a variable speed switch 66 which communicates control signals to thecompression pumps 48A, 48B via data communication means 76. For example,but without limitation, data communication means 76 may be electricalwires, or via wireless networking.

The central processing unit 52 may further use the table 64 to determinewhether a warning that the storage tank 44 is approaching itspredetermined maximum capacity for liquefied gas, or the storage tank 44has reached maximum capacity. The warning can be issued locally to thecontrol unit 50, at one or more locations remote from the control unit50 or both. If the maximum capacity of the storage tank 44 has beenreached the variable speed switch 66 may switch of the compression pumps48A, 48B.

If there are any gasses that pass into the storage tank 44 which do notliquefy, those gasses may flow through a conduit 72 to a flare stackwhere that remaining gas can be flared. The volume of that gas, andhence the carbon footprint associated with that flaring is substantiallylower than would have been the case if the rich gas were flared withoutbeing treated according to the method of the present invention.Alternatively, conduit 72 may be routed so that it feeds those gassesback into conduit 36.

The above description is meant to be exemplary only, and one skilled inthe art will recognize that changes may be made to the embodimentsdescribed without departing from the scope of the invention disclosed.Still other modifications which fall within the scope of the presentinvention will be apparent to those skilled in the art, in light of areview of this disclosure.

Various aspects of the method and apparatus disclosed in the variousembodiments, examples and drawings of this disclosure may be used alone,in combination, or in a variety of arrangements not specificallydiscussed in the embodiments, examples and drawings described above.This disclosure is therefore not limited in its application to thedetails and arrangement of components set forth in the above descriptionor illustrated in the drawings. For example, aspects described in oneembodiment may be combined in any manner with aspects described in otherembodiments. Although particular embodiments have been shown anddescribed, it will be obvious to those skilled in the art that changesand modifications may be made without departing from this invention inits broader aspects. The scope of the following claims should not belimited by the embodiments set forth in the examples, but should begiven the broadest reasonable interpretation consistent with thedescription as a whole.

1-24. (canceled)
 25. An apparatus comprising: one or more first conduitsfor providing a first rich gas composition from a heater treater to afirst compressor, wherein crude oil flowed to a 2-phase separator formsa sales gas stream and a liquid hydrocarbon stream, the liquidhydrocarbon stream is flowed to the heater treater to form an oil streamand the first rich composition comprising less than 50 mol % methane,and the first compressor is configured to compress the first rich gascomposition; one or more second conduits for providing a second rich gascomposition from an oil storage tank to a second compressor, wherein theoil stream is flowed to the oil storage tank, the second rich gascomposition comprising less than 50 mol % methane is in a headspace ofthe oil storage tank, and the second compressor is configured tocompress the second rich gas composition; and one or more condensers forcooling the compressed first rich gas composition and the compressedsecond rich gas composition so that a portion thereof condenses to forma liquified gas and liquified gas vapor in the condenser.
 26. Theapparatus of claim 25, wherein the first compressor and secondcompressor are each associated with one or more third conduits providingthe compressed first rich gas composition and the compressed second richgas composition to the one or more condensers.
 27. The apparatus ofclaim 25, wherein the first and second rich gas composition have a gaugepressure of less than or equal to 1379 kPa.
 28. The apparatus of claim25, wherein the one or more condensers discharge the liquefied gas andliquefied gas vapor into one or more storage means.
 29. The apparatus ofclaim 28, wherein the at least one storage means is a storage tank. 30.The apparatus of claim 25, wherein the one or more condensers comprise afan-cooled condenser.
 31. The apparatus of claim 25, wherein theapparatus is configured such that the first and/or second rich gascomposition is gathered from one or more additional sources, the one ormore additional sources being selected from a two-phase separator and avapor recovery tower.
 32. The apparatus of claim 25, wherein: each ofthe first and second compressors is controlled by a control unit, thecontrol unit comprises a central processor unit and at least onepressure sensor adapted to measure a source pressure, the sourcepressure is the pressure of the first or second rich gas composition ata source of such gas, and the central processor unit turns off eachcompression pump associated with that source when the source pressure isat or below a predetermined pressure.
 33. The apparatus of claim 25,wherein the first and second compressor compresses the first and secondrich gas composition to a gauge pressure of in the range of 1379 to 2068kPa.
 34. The apparatus of claim 25, wherein the apparatus is configuredto remove at least a portion of any sulfur, oxygen, and water from thefirst and/or second rich gas composition upstream of the one or morecondensers.
 35. The apparatus of claim 34, wherein the apparatus furthercomprises one or more gas cleaners for removing at least a portion ofany sulfur, oxygen, and water in the first and/or second rich gascomposition upstream of the one or more condensers.
 36. The apparatus ofclaim 25, wherein the apparatus is configured to reduce the amount ofgas flared from a well pad or an oil production facility.
 37. Theapparatus of claim 25, wherein the one or more condensers dischargenon-condensed gas therefrom.
 38. The apparatus of claim 37, wherein thenon-condensed gas comprises a higher proportion of methane than thefirst and second rich gas composition.
 39. The apparatus of claim 37,wherein the non-condensed gas is added to the storage tank.
 40. Theapparatus of claim 37, wherein the non-condensed gas is added to theheater treater along with the hydrocarbon stream.
 41. The apparatus ofclaim 37, further comprising a third compressor for compressing thenon-condensed gas and adding the compressed product thereof to thecompressed first rich gas composition and compressed second rich gascomposition that is cooled in the condenser.
 42. The apparatus of claim37, wherein the apparatus is configured to burn the non-condensed gasand generating electricity therefrom.
 43. The apparatus of claim 25,wherein the apparatus is configured to introduce the sales gas, naturalgas formed therefrom, and/or a purified product of the sales gas into astream of commerce.
 44. An apparatus comprising: one or more firstconduits for providing a first rich gas composition from a heatertreater to a compressor, wherein crude oil flowed to a 2-phase separatorforms a sales gas stream and a liquid hydrocarbon stream, the liquidhydrocarbon stream is flowed to the heater treater to form an oil streamand the first rich composition comprising less than 50 mol % methane,and the compressor is configured to compress the first rich gascomposition; one or more second conduits for providing a second rich gascomposition from an oil storage tank to the compressor, wherein the oilstream is flowed to the oil storage tank, the second rich gascomposition comprising less than 50 mol % methane is in a headspace ofthe oil storage tank, and the compressor is configured to compress thesecond rich gas composition; and one or more condensers for cooling thecompressed first rich gas composition and the compressed second rich gascomposition so that a portion thereof condenses to form a liquified gasand liquified gas vapor in the condenser.